APRIL 2015
Waiting For The Rebound
Drilling Plans, Strategies For Low Oil Page 12, 44
Plus
Service Cost Reduction Survey Page 54
AND
Production Data By County Page 34
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CONTENTS
APRIL 2015
VOLUME 3 ISSUE 4
Pg 34
PRODUCTS & TECHNOLOGY
Navigating Bakken Data
A team of former frack sand managers and data analysts have formed a new downhole data report capable of revealing unique, customized Bakken data sets to everyone from transload site supervisors to major energy service firms. BY LUKE GEIVER
Pg 44
EXPLORATION & PRODUCTION
Dealing With Rig Decline
For drilling component manufacturers and drilling consultants, the current rig count presents a challenge: focus on existing drill-related offerings or pivot attention to other non-drilling service offerings. BY EMILY AASAND
DEPARTMENTS
IN PLAY
Pg 26
INFRASTRUCTURE & CONSTRUCTION
Then And Now: Bakken Economy By The Numbers
Numbers are in for an economic study that pinpoints the massive fiscal impact of the Bakken on North Dakota. The author explains the results and how they may evolve in the future. BY PATRICK C. MILLER
54 Citadel Survey: Oil, gas service firms asked to cut prices
Service providers share views on cost reduction requests, anticipated workforce reduction plans, and more in new survey. BY EMILY AASAND
6 Editor’s Note
Expand Your Bakken Knowledge BY LUKE GEIVER
8 ND Petroleum Council When we become Big Oil BY TESSA SANDSTROM
ON THE COVER: Drilling rig pipe sits at a future well site. PHOTO: GAYLON WAMPLER
10 Events Calendar 12 Bakken News
Bakken News and Trends
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5
EDITOR'S NOTE
Expand Your Bakken Knowledge At a time when oil price uncertainty is guiding budget plans and drilling rig activity, knowledge truly is power.
Luke Geiver
Editor The Bakken magazine lgeiver@bbiinternational.com
For the Latest Industry News:
The hardcore desire of energy service firms, material transporters and operators of all sizes to find efficiencies has put a premium on information capable of justifying workforce retention, increasing well productivity, extending rig contracts or, in some cases, reducing service costs. For this month’s issue, we chose several data-heavy, information-rich stories as a way to be a part of the solution for those looking to expand their respective Bakken knowledge bases on everything from downhole consumable trends to executive team sentiments on workforce retention plans. The current oil price environment has moved many in the Bakken industry past the rig-chasing, get-it-done-fast mentality. Today, as oil hovers in the $50/barrel range, the time to make informed, well-researched decisions is now because every barrel—and the fiscal reverberations that follow—counts. Sean Morgan understands the power of data. A former frack sand supply manager for a major U.S. operation, Morgan had seen how data—or lack thereof—can impact an operation. After Morgan and his team realized they were consistently reacting slowly to the evolving Bakken frack sand demand market, they turned to information to help them ship certain sand types to certain sand storage locations during the optimal time. With a compilation of downhole data, operator specific proppant usage and several other metrics, they turned a frack sand operation plagued with demurrage charges into a more efficient business. Navport analysts provided a one-off report on our wish list of the information sectors we wanted to offer for “Navigating Bakken Data,” on page 34. It tells of Morgan and crew’s unique journey to the formation of a data-centric team and features an unprecedented look at proppant trends, production by operator and other valuable insights in the North Dakota counties of McKenzie, Dunn, Mountrail and Williams. You can find which operators are producing the most oil with the least amount of proppant, among many other conclusions. To shed light on the current service cost-reduction trending in every major energy play in the U.S., we dissected an oil and gas survey that highlights energy service companies' views on the topic. Citadel Advisory Group, a boutique investment banking firm, told us that as crude prices fell and operators pushed for service-cost reductions, their phones rang constantly with calls from energy service firms, investors and others looking to see if, and how much, costs would or could be reduced. “Executives wanted guidance,” they told Emily Aasand for her story, “Dealing with Rig Decline, page 44, “others just wanted reassurance.” A study recently completed by a team of North Dakota State University economists provides definitive assurance that the Bakken has, and is having, an incredible economic impact on the state. It provides data to support what the Bakken’s fiscal role has been the past five-plus years. Patrick Miller, staff writer, reviewed the study and spoke with each author of the study. His work for the story on page 54, reveals how accurate the study is, and more importantly, how it may change after it is completed two years from now. We hope you enjoy this month’s issue and add to your own Bakken knowledge at a time when rig count, wellproductivity per rig, break-even costs and the other important terms of the Bakken circa 2015 are prevalent, because as we all know, knowledge is a powerful thing.
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NORTH DAKOTA PETROLEUM COUNCIL
THE MESSAGE
For many of us growing up in Small Town, North Dakota, the opportunities for staying in your hometown after high school or college were once fairly limited. For
SMALLTOWN TO OIL HUB: Watford City, North Dakota's streets are filled every summer during its annual ribfest. The event draws a large gathering of oilfield-related workers living in the area.
When we become Big Oil By Tessa Sandstrom
8
The BAKKEN MAGAZINE APRIL 2015
the majority of women, apart from working in retail (if your small town were lucky enough to have retail stores), you might have been able to become a teacher. Or, you could marry a farmer. For men, you could also try to find a teaching job or you could farm or work for the local construction firm. The opportunities for something more specialized like engineering, marketing, finance or public relations were slim, even in our larger cities. Today that’s not the case, and anyone who has read this column has heard me preach it time and time again. Yet, I always find myself coming back to this point because it seems like this is something that is so often lost in the rhetoric of politics and activism that surrounds oil. Upon the release of a study outlining the contributions of oil and gas development in our state and communities, many of these thoughts and ideas resurfaced. In case you missed it—and you may have because it wasn’t heavily covered in newspapers—researchers at North Dakota State University found that the oil and gas industry contributed $43 billion to the state’s economy in 2013. About $25.3 billion of this was in secondary impacts, or the respending of the $17.7 billion spent directly by the industry. The largest benefactor of these dollars was retail trade, or the businesses
NORTH DAKOTA PETROLEUM COUNCIL
that sell the products and services needed by the industry and employees. They pulled in a whopping $11.3 billion of that total. Households (or individuals), were the second largest, bringing in $9.3 billion in salaries, wages, royalties and other income. Government revenues were slightly behind the finance, insurance and real estate industry at $4.4 billion. Seven other industries also pulled in almost a billion or more each. Most will agree that these are significant sums, but even I find myself numbed to those figures because these are sums that are just incomprehensible to me. What does this mean to me? What does it mean to you? The short answer is “a lot.” For starters, that $9.3 billion that went to households includes $6.3 billion paid out in salaries and wages alone. That represents 35.9 percent of all private sector salaries and wages paid in the entire state. This should come as no surprise if you consider that the 81,000 jobs supported by oil and gas in 2013 represents about 20 percent of the entire North Dakota workforce. Those salaries spent by those 81,000 people are being spent in our businesses, our restaurants and our towns, sending ripple effects through the entire state’s economy. Again, a lot of numbers, but what’s important is not necessarily the numbers, but the human factor that is behind each one of them. “Six degrees of separation” is a theory that most of us are likely familiar with and it states that every person is only six people or steps
OIL PLANS: Former Williston Mayor Ward Koeser had to revamp the city's mayoral duties because of oil development.
away by introduction to another person. In North Dakota, we’re more accustomed to about two or three degrees of separation. Chances are high that any stranger you meet knows someone you know. I would predict the same goes for the oil industry. Even if you don’t have an immediate family member or friend employed in or by the oil industry, chances are your friend or family member does. In my hometown, many of my friends not only work in the oil industry, but they own their own businesses and employ dozens of other individuals. For this very reason, when I hear accusations or derogatory comments lodged at Big Oil, I can’t help but be slightly offended. For me, the oil industry doesn’t represent some faceless out-of-state corporation; it represents Devin, Loren, Jake and James—all individuals who started
their own businesses to support activities in the oilfield and created dozens of jobs at the same time. Since they are not large corporations, but rather small business owners, I would guess they are not considered Big Oil. If not, at what point do they become Big Oil? After all, the companies considered Big Oil started out as small businesses and it was through success and hard work that they became the larger corporations that they are today. I can only wish the small business owners in North Dakota the same success. The oil industry to me also represents Garrett, Josh, Drew and Kyle who work for major operators. Their job is to help ensure development is done as responsibly as possible and that their neighbors’ homes, farms and water resources are protected. Are they just Big Oil or are they exempt because they were born and raised in western North Dakota? You see, with an economic
impact of $43 billion, Big Oil is made up of each and every one of the individuals who have found an opportunity to make a living or start their own businesses. It’s made up of individuals who care about their hometowns and want to do the best job possible while providing a valuable resource to our state and nation. Big Oil is not some faceless entity located elsewhere. No, Big Oil is you and me. Author: Tessa Sandstrom Communications Manager, North Dakota Petroleum Council tsandstrom@ndoil.org 701-557-7744
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The BAKKEN MAGAZINE APRIL 2015
BAKKEN NEWS & TRENDS
BAKKEN NEWS
Early 2015 Operator Update Industry’s outlook on the oil price environment
The current oil price market has most exploration and production companies looking at ways to position themselves to continue success in the Bakken—whether that be reducing drilling rig numbers or finding ways to decrease well head costs. It has companies cutting 2015 budget projections and has companies tightening or eliminating well completion testing strategies. Due to low oil prices, EOG Resources Inc. said the number of wells drilled and completed this year by the company will decrease. EOG said its primary goal for 2015 is to position the company to resume long-term growth once crude oil prices recover and emphasized that it’s not interested in accelerating crude oil production in a low-price environment. Triangle Petroleum Corp, has delayed all operated well completions until May or longer, “subject to commodity prices and gaps in the RockPile third-party completion schedule.” Although delayed, Triangle plans to have up to 24 wells awaiting completion as of May 2015. WPX Energy hedged roughly three-fourths of its anticipated 2015 natural gas production and roughly two-thirds of expected oil production this year at an average price of $94.88 per barrel, while Oasis Petroleum said it plans to reduce drilling rigs along with fewer completed wells and that wells brought onto production in 2015 will keep the company’s 2015 growth profile relatively flat. One company not planning to adjust its business model to accommodate the oil price commodity is Whiting Petroleum Corp. During Whiting’s fourth quarter and 2015 guidance investor’s call, James Volker, president and CEO reiterated to analysts that Whiting is not postponing completions or relying on the oil price curve to make its operations economical. “We are relying on ourselves to make money in the current oil price environment,” he said. “We are set to prosper at current oil prices.” Volker believes Whiting’s efficient operations and leadership in implementing new completion technologies will help overcome the impact of lower crude prices.
EOG Resources Inc.
Despite decreased production estimations for 2015, EOG Resources Inc. exits 2014 on a fiscal and operational high-note. The company reported 2014 fourth-quarter net income of $445 million, and also saw an increase in overall U.S. crude oil and condensate production by nearly 28 percent. EOG also completed a six-well pattern in the Bakken core spaced at 700 feet between wells to produce a combined initial production rate of 9,450 barrels of oil per day (bopd) in 2014. EOG plans to perform additional pilots and testing in 2015 to establish the best long-term development plan for the play. “EOG delivered both high returns and strong growth in 2014, a unique accomplishment in the energy sector,” said William Thomas, chairman and CEO. “Our returns-focused capital discipline has been at the core of EOG’s culture since the very beginning. We are confident we will continue to earn healthy returns on our capital program during this commodity down cycle and, more importantly, emerge stronger and poised for significant long-term growth.” For Feb. 1 through June 30, EOG has crude financial price swap contracts in place for 47,000 bopd at a weighted average price of $91.22 per barrel and for July 1 through Dec. 31, EOG has crude financial price swap contracts in place for 10,000 bopd at a weighted average price of $89.98 per barrel, the company said.
Marathon Oil
Marathon Oil Corp.’s 2014 fourth quarter Bakken activity averaged 55,000 net barrels of oil per day (bopd) of production, a 38 percent increase from the year-ago average, due to increased density pad drilling and the timing of bringing wells to sale. Marathon researched total depth on 23 gross wells and brought 17 gross operated well stop sale, the company said in its Q4 earnings report, 15 of which piloted enhanced completions. The enhanced completion designs achieved promising results with 42 of 55 tests online, the company said, adding that 18 pilot completion wells averaged more than 30 percent uplifting in cumulative production over the first 60 days. “The Bakken enhanced completion design pilot program is achieving promising early results with 42 or the 55 tests online at year end,” Marathon said. “The initial results based on 18 wells, are showing greater than 30 percent improvement in cumulative production after 60 days, compared to direct offset performance.” The company also finished drilling two high-density spacing pilots in Bakken shale play—six wells per horizon—that are awaiting completion. “Though we have rightly focused on prudent near-term actions, Marathon Oil has laid the groundwork for the future by growing our U.S. unconventional net 2P resource by 20 percent in 2014,” said Lee Tillman, president and CEO. “Our asset teams continue to aggressively test downspacing, completion designs, co-development and new horizons which offer the potential to add further to our 3 billion barrels of oil equivalent of net 2P unconventional resource.”
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13
BAKKEN NEWS
Early 2015 Operator Update continued
Whiting Petroleum Corp.
Triangle Petroleum Corp.
Triangle Petroleum Corp. unveiled its capital budget outlook and guidance for its exploration and production division, RockPile Energy Services, as well as an update on Caliber Midstream for fiscal year 2016 (2015). Triangle’s 2016 capital expenditure budget totals between $165 million and $195 million— a 71 percent year-over-year reduction. Triangle plans to spend up to $165 million on exploration and production operated drilling programs, up to $10 million on exploration and production in non-operated drilling programs, and up to $20 million on its RockPile segment. The 2016 budget “allows Triangle to respond quickly to any improvement in commodity pricing and to return daily production numbers to at or above Dec. 31, exit rate numbers.� With a near $165 million 2016 fiscal year budget, Triangle anticipates a fiscal year total between 11,000 barrels of oil equivalent per day (boepd) and 13,000 boepd.
Whiting Petroleum Corp. is currently running 16 drilling rigs in the Williston Basin and by mid-year, it expects to run 13. For 2015, Whiting intends to spend roughly $2 billion, 67 percent of which will be spent on its northern Rockies and central Rockies property areas that include the Williston Basin and the Niobrara. In 2014, the company experienced production gains of more than 30 percent for its 30-, 60- and 90-day initial production rates. The combination of its IP rates increases and decreases well costs that have declined from $8.5 million to less than $7 million, have the Whiting team confident 2015 will be another year of growth. Mark Williams, senior vice president of exploration and production, said that although slickwater fracks may not be the appropriate approach for every portion of the Williston Basin, many of Whiting’s core acreage blocks meet the requirements for Whiting to deploy slickwater methodologies. “If you look at what has been happening with completion technology over the last three years,� Williams said, “we have been in a period of rapid change.� Whiting’s commitment to learning more about the Williston Basin is one of the main reasons James Volker, president and CEO of the Denver-based exploration and production company, believes his North Dakota team can reduce well costs. According to Volker, there have been roughly 300 core samples taken across the Williston Basin and Whiting’s geoscience team has examined and described 234 of those. “We have here at Whiting what we think is the database necessary to customize the completions that we are doing in each one of our key project areas,� Volker said. “I can’t overemphasize that because that is what we can use to drive down our costs in each area.� By the end of 2016, Volker expects that roughly 50 percent of Whiting’s expected production will be hedged with three-way collars offering a low price of $55 per barrel and a ceiling price in the $60 to $70 range. With the reduced rig count by midyear in the Williston Basin, Volker expects 2015 Bakken and Three Forks production to remain relatively flat compared to 2014. The goal for 2016 is similar to that of 2015, he added. “I really believe we could have a lower budget and still see more growth in 2016. That is our goal,� he said, and the company can do that by concentrating on its highest rate of return areas while it continues to drive down costs.
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BAKKEN NEWS
Oasis Petroleum
WPX Energy
WPX Energy announced a 2015 capital investment plan of $725 million, roughly half the amount of its capital plan last year, with up to $225 million planned for the company’s Williston Basin activity. “Our capital plan is prudent, disciplined and consistent with our long-term focus,” said Rick Muncrief, WPX president and CEO. “At the same time, we have financial and operational flexibility because of how well we executed over the past year, completing asset sales, increasing oil volumes and heavily hedging our 2015 production at very favorable prices.” WPX started 2015 with five rigs in the Williston Basin and plans to scale back to one rig by late spring for the remainder of the year. “Headwinds bring challenges and opportunities,” said Muncrief. “We’re ready for both. It’s why we have a long-term plan to reshape WPX and grow our margins and cash flow. Margin expansion comes from diversifying our production and right sizing our cost structure.”
In 2013, Oasis Petroleum produced an average of 33,904 barrels of oil equivalent per day (boepd), but by the end of 2014, the exploration and production firm increased its average daily oil production to 45,656 boepd—a 35 percent increase. In the fourth quarter of 2014, Oasis exceeded its production guidance range, reaching an average of 50,143 boepd. But, according to the company, a drilling rig reduction plan along with fewer completed wells and wells brought onto production in 2015 will keep the country’s 2015 growth profile relatively flat. In 2014, Oasis completed and placed on production 195 gross wells, including 48 in the fourth quarter. As of December 31, 2014, the company has 72 wells awaiting completion. The West Williston project area accounted for 32,416 boepd of the company’s Q4 production total of 50,143 boepd. After downspacing tests, subsurface modeling, project evaluations and adjustments made after 2014 well completions, Oasis has changed its drilling inventory assumptions. In its Montana acreage blocks, the company believes it will drill seven wells per drilling spacing unit (DSU) in its 216 DSUs. For the Indian Hills and South Cottonwood areas found in North Dakota—areas that account for 72 DSUs—Oasis expects to drill 15 wells per DSU. Of its 405 total operated DSUs, the company believes it has a remaining inventory of 3,046 gross operated drilling locations. The budget plans for 2015 include a total of $705 million, with the majority of the budget slated for drilling and completions. “We also see the opportunity to further improve returns through enhanced completions, which we expect to represent approximately 60 percent of our program in 2015,” said Thomas Nusz, chairman and CEO. Oasis intends to complete the majority of its wells by its in-house completion team, Oasis Well Services. OWS has two frack spreads with a combined 40,000 horsepower. Through the use of OWS, the company was able to save roughly $380,000 per well in 2014. On its slickwater fracks, OWS provided average well savings of $650,000. Although the company will continue to rely on its fracking service, Oasis is considering a sale of its midstream business that includes saltwater disposal wells and pipelines.
THEBAKKEN.COM
15
BAKKEN NEWS
New USGS resource assessment map, same Williston Basin disparity The U.S. Geological Survey has issued an updated map showing the assessed continuous oil resources in the U.S. The updated map reconfirms that the Williston Basin, including the Bakken and Three Forks pool, is the largest continuous oil resource ever assessed by the USGS. At 7.38 billion barrels of oil, 6.7 trillion cubic feet of associated natural gas and 527 million barrels of natural gas liquids, the shale resource ranks as the largest in the U.S. followed by the Eagle Ford formation in Texas at 1.73 bbo. Although the updated map is new, the USGS assessment of the Williston Basin is not, despite differing numbers from industry.
16
Although the USGS did reassess and update its estimates of the Williston Basin in 2013, there has been little change since. In 2013, the USGS reissued its assessment of the Williston Basin, increasing its estimate to 7.38 billion barrels of oil. The estimate was reached using new well data and additional information on the Three Forks formations. The numeric value for the resource was determined using a high and low estimate. For the USGS, the amount of oil in place for the Williston Basin could range from 3 bbo to 11 bbo. Before the USGS provided its 2013 reassessment of the Williston Basin, the majority of the
The BAKKEN MAGAZINE APRIL 2015
oil industry believed the play held much more oil. And, even after the 2013 estimate update, industry still felt the numbers were too low. The North Dakota Department of Mineral Resources believes the Williston Basin holds roughly 11
bbo to 17 bbo. Others, like the North Dakota-based research institution Energy & Environmental Research Center, believe the play could hold more than 50 bbo.
BAKKEN NEWS
Analysts: price trough, M&A activity, survival tactics
PIPEPLUS
Tim Perry, head of the oil and gas division at the global financial services firm Credit Suisse, should be popular among the broad energy industry. During a presentation to the oil and gas industry in February, Perry said it is his belief that the worst of the low oil prices will be over sooner than most believe. In fact, he said, the price trend trough will transform back towards much higher prices in 2015. Geoff Davis, managing director at Morgan Stanley, believes that oil prices are not about financial issues faced by the U.S.— as they were in 2008—and are instead, about the simple truths of supply and demand. And, any
global economic stagnation that some have predicted may impact prices will not affect oil prices in 2015. Oil prices could create a high-level of merger and acquisition activity in the North American shale energy industry. According to Davis, companies within the industry fall into three categories: large cap investment grade (healthy, screening potential opportunities); middle range with modest leverage (working, hunkering down and focused on survival); and distressed (worst assets among peer groups, high debt). Dan Pratt, director of valuation at HIS Inc., believes that activity levels for mergers and
acquisitions could ramp up during the second half of 2015. “There is a lot of motivation for large companies to come out of this stronger,� he said. Companies looking to add assets will be better off using stock options as opposed to paying cash, Pratt believes. For the firms looking to survive the low crude price environment, Perry said many will retreat to their best acreage blocks. Many of those areas could, or should, have multiple productive geographic benches. The move to the multizone acreage means many operators will be harvesting some of their best available acreage today rather than saving it for future work.
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BAKKEN NEWS
Low prices spur innovation, executives share strategies
Oil and gas production companies accustomed to the fast-paced, high-demand business culture of chasing rigs, scrambling to permit wells or source water and other materials for the past five years are now working to shift their company-wide perception of the industry. Low oil prices have changed the activity levels for nearly every energy-related firm working in the major U.S. shale plays. Company strategies have also changed. Ken Mariani, president of exploration and production firm Enervest Ltd., believes employees previously engaged and focused solely on drilling-related work can now pursue new skills and educate themselves
for other positions. “This is an opportunity for flexible employees,” Mariani said earlier this year at the North American Prospect Expo in Houston. Managers, supervisors and human resource personnel are also in the midst of a unique situation not seen the past five years: talent abundance. Gary Evans, chairman and CEO of Magnum Hunter Resources Corp., a natural gas-focused independent production company, believes that as certain firms allow employee contracts to expire, others can acquire previously unattainable talent. Some firms have created internal protocol and programs to maintain talent
TIED TO MANY JOBS: During times of decreased activities, employeers of all size hope employees work to educate themselves on new skills and learn new job duties. PHOTO: ANADARKO PETROLUEM CORP.
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during times of reduced activity, however. Anadarko Petroleum Corp., an Eagle Ford operator that also works offshore, has a wellestablished employee mentoring program that Kurt McCaslin, vice president of project management for the company’s onshore assets, said is valuable during down times. The program pairs experienced employees with newer team members to help explain the cyclical nature of the industry all in an effort to retain younger workers. In addition to employee acquisition or retention efforts, most energy-related firms will research possible equipment changes or process efficiency tweaks.
Evans’ team will consider purchasing more equipment to limit the company’s exposure to rental markets, and Mariani said other firms will explore research into basin-wide studies. “Low oil prices will drive innovation,” Mariani said. Effective strategies deployed in the current low oil price environment will pay off, according to McCaslin. “If we can prove that we can get the costs down and make money at this price point for oil the money [investment] will be there when oil prices recover,” he said.
NEW TRADE TOOLS: For some firms, downtime finally allows for research into new tooling options for drilling, completions and other oilfield-related work. PHOTO: ANADARKO PETROLEUM CORP.
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BAKKEN NEWS
Keystone XL, Vantage pipeline: What’s next?
The Vantage pipeline and the proposed Keystone XL pipeline do, or would, cross the U.S./Canadian border into the North Dakota portion of the Bakken shale play. That is the only similarity between the progress and usefulness of each.
Natural gas liquids lead way
Vantage Pipeline is a 430-mile long, high-vapor pressure line built to transfer natural gas liquids from Tioga, North Dakota, through Saskatchewan before terminating in Empress, Alberta. Pembina Pipeline Corp., the Calgary-based midstream firm that recently purchased the asset, has announced plans to expand the pipeline’s capacity from 40,000 barrels per day to roughly 70,000 bpd. The expansion plans include the addition of new
pump stations along with a 50-mile stretch of 8-inch gathering line. Pembina believes the pipeline and expansions at the Saskatchewan Ethane Extraction Plant will create EBIDTA earnings—earnings before interest, taxes, depreciation and amoritization—of $75 million to $110 million. The company is also looking at other ways to seize the natural gas liquids feedstock availability in the Wil-
liston Basin, including another Vantage expansion to bring more ethane to the SEED facility. For methane, Pembina sees the construction of more processing infrastructure as an opportunity. For propane and butane, it believes both could be used to support its proposed propane export terminal in Portland. And, the remaining gas stream condensates could be used as supply for Pembina’s
Canadian Diluent Hub. “Recent flaring regulations are going to kick off opportunities for processing,” Stu Taylor, senior vice president of gas for Pembina said in regards to the Vantage Pipeline acquisition and the company’s exposure to the Bakken. “We are excited about the Bakken opportunity from an NGL perspective.”
Bakken NGL egress & opportunity
Methane Ethane
Current Egress Alternatives
Potential Opportunities
Transported on Third Party pipelines
Construction of straddle plant infrastructure
Vantage Pipeline
Further expansion of the Vantage Pipeline
Transported on Third Party pipelines Propane
Local Market Sales Pipeline/Rail Exports
Butane
Source of supply for porential propane export terminal
Local Market Sales Pipeline/Rail Exports
Condensates
Pipeline/Rail Exports
Source of supply for Pembina’s Canadian Diluent Hub
IMAGE: PEMBINA PIPELINE CORP.
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BAKKEN NEWS
State Department, future bills offer hope
The U.S. Senate’s opportunity to pass a stand-alone bill approving the Keystone XL pipeline from Canada to Cushing, Oklahoma, may have passed, but TransCanada and other Keystone backers believe other opportunities exist. Sen. John Hoeven, RN.D., said that he would continue to push the passing of a Keystone bill after the senate fell five votes short of the super majority needed to override a presidential veto of a Keystone bill that had previously passed through Congress. “At this point, we will continue to press for approval of the Keystone XL pipeline by attaching a similar measure to another must-pass bill, perhaps an energy, transportation or appropriations bill,” he said. Sen. Heidi Heitkamp, D-N.D., had previ-
ere
Wh
ously recruited 10 Democrats to vote in favor of the Keystone bill. Heitkamp said she would work to do the same on future bills. Rep. Kevin Cramer, R-N.D., who sponsored a bill on the pipeline, also said he would continue to help a Keystone approval package get signed. TransCanada, the company hoping to construct and operate the 1,179-mile, 36-inch diameter pipeline that could transport 830,000 barrels of oil per day to the Gulf Coast, is looking to the U.S. State Department. “This is definitely a project that’s in the interest of the United States. We’re very hopeful that the president and the administration will see it that way,” Mark Cooper, spokesperson for TransCanada, said. “Whatever results we get, we’re going to keep our options open for our next step. That
NGL Production Forecast
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IMAGE: PEMBINA PIPELINE CORP.
could very well be continuing on and moving forward,” he said, “but until we actually see that decision from the State Department, I’m not going to speculate on what our next steps will be.” According to Cooper, TransCanada has tried to stay away from the political process as much as possible in its attempts to get the project approved. The project has often drawn both praise and criticism of its job creation ability.
Cooper said the company has no qualms about the topic of jobs. “We make no apologies for the fact that we provide construction jobs for American men and women. The people who have these jobs string them together to make a career. Without temporary jobs, we wouldn’t have the Empire State Building, the Golden Gate Bridge or the Hoover Dam.”
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BAKKEN NEWS
Oil Production Rate (STB/Day)
Flared gas injected to increase Bakken production 500 450 400 350 300 250 200 150 100 50 0
Oil Production without Gas Injection (compositional model) Oil Production with Separator Gas Injection (compositional model)
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Associated gas produced during oil retrieval can be flared, captured, compressed and now thanks to a researcher from of the University of Montana, injected back downhole to enhance oil recovery. Todd Hoffman, assistant professor, is currently working to prove and perfect a process to
capture, pressurize and inject associated gas from the Williston Basin back into the Bakken or Three Forks formations to increase well productivity and drastically reduce flared gas. Once injected at proper pressure, the gas acts similar to CO2 used for EOR. Because the gas is pressurized to the same level as the
oil, it mixes into the oil and causes it to swell. Once swollen, the oil is forced to break from the rock and into a fractured pathway leading to the wellbore. To make the injection process happen, a natural gas compressor has to be present on the well site, along with gathering and injec-
tion lines. Hoffman said that the process can be economically viable at a wide range of oil prices. In one base scenario, a $16 million investment into a multiwell pad could be paid back in 5.8 years for a rate of return on investment of 22 percent. Hoffman and his team of researchers expect more results by late summer. The team has already modeled how the system would work on a multi-well pad with four wells producing gas to be injected into one well. With core samples from North Dakota, the team is also modeling what a gas flood injection would look like in the rock. “The idea is that operators get more well productivity, they prevent flaring and they can sell that injected gas at a later date,” Hoffman said.
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BAKKEN NEWS
Surge funding sends $1.1 billion to oil counties, state, DOT Come spring, regions most in need of infrastructure updates in western North Dakota will have state funding available. Through the passage of SB 2103—a bill providing one-time surge funding from North Dakota to counties, cities and townships— roughly $298 million will be spent on road construction, water projects and others. The funding was sped through the legislature and then again by Kelley Schmidt, state treasurer. “The extraordinary efforts of my staff and our political subdivisions allowed us to complete the certification process in just a few days,” she said. “This enables us to get those dollars where they are needed in record time.” Nearly every county in the state received funding from SB 2103, and, hub cities Williston, Dickinson, Minot and Watford City received $172 million. In total, 90 North Dakota cities received funding. Funding for the bill came from the state’s Strategic Improvement Fund, a fund made up entirely of cash. An Upper Great Plains Transportation Institute study was used to determine which areas of the state were in greatest need.
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EXPLORATION & PRODUCTION
THEN AND NOW: Bakken Economy By The Numbers Results of an economic study show where the oil and gas industry has been, but knowing where it’s going is the challenge. By Patrick C. Miller
Announcing that North Dakota’s oil and gas industry had a tremendous impact on the state’s economy in 2013 might seem like the setup for a well-known car insurance company’s “Everybody knows that” TV commercial.
Well, did you know that with a total economic impact of $43 billion in 2013—in just eight years—the industry’s contribution to North Dakota economy has grown nearly eight times beyond the level it was at before the Bakken oil boom began? While this might not be as entertaining as knowing that Old McDonald couldn’t spell a word without including E-I-E-I-O as that popular insurance commercial reminded us, well-researched data is what transforms a widely held assumption into a verifiable fact. Since 2005, the North Dakota Petroleum Council has commissioned a biennial study conducted by the North Dakota State University Department of Agribusiness and Applied Economics to measure the impact of the oil and gas industry on the state’s economy. NDSU research scientist Dean Bangsund presented study results last month during Energy Day at the State Capitol Building in Bismarck. “The numbers that we pulled together from 2013 are tremendously large, more so than what we’ve found with any study we’ve done to this point,” Bangsund noted during his talk. For example, the $43 billion economic impact of the oil and gas industry is a 750 percent increase in the industry’s size since 2005, the first year the study was conducted. This represents a 303 percent increase in total jobs supported by the industry and a 991 percent increase in direct jobs. SUDDEN IMPACT: North Dakota State University research scientist Dean Bangsund presents the results of a study detailing the Bakken's economic impact during Energy Day at the State Capitol Building in Bismarck. PHOTO: THE BAKKEN MAGAZINE
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EXPLORATION & PRODUCTION
The total number of direct jobs in the industry has expanded from 5,051 in 2005 to nearly 41,000 in 2011 and to 55,137 in 2013. In 2013, secondary employment added another 26,403 jobs for a total of 81,540, a 37 percent increase over 2011. Nancy Hodur, an NDSU research assistant professor who co-authored the study, says that the results are accurate because they’re based on data supplied by the industry. “We go directly to the industry, we ask them what their expenditures are and they tell us,” she explains. “It’s challenging to collect the data, but it also makes a very valid and defensible statement.” Hodur says providing accurate data for the study is in the best interest of the industry. “There’s not a magic pot of data that you can just go claim,” Hodur notes. “They’re actually sharing with us confidential information about what they’re spending.
We aggregate it and then are able to draw a picture and a description of the effect of the industry on the overall economy.” According to the NDSU study, there were 2,183 wells completed in 2013 with an average monthly rig count of 185, which Bangsund says grew from a $1.4 billion impact in 2005 to a $20.4 billion impact in 2013. The study shows that in 2013, there was an average impact of $860,000 per well of in-state expenditures, creating $1.7 million of direct and secondary expenditures and 2.4 direct and secondary jobs. Each well generated an average of $324,000 in severance tax and $23,500 in other taxes, such as sales, personal income, corporate and property. Each drilling rig generated an average of $40 million of in-state expenditures and $105 million in direct and secondary impacts, creating 177 direct and secondary jobs, as well as $1.4 million in tax revenue.
Bangsund says that North Dakotans have an intense interest in royalty rates, another area covered in the study. “What does this mean for the people who own the minerals?” he asks. “The survey data we got this time around was very consistent with the survey data we got in 2011. The royalty rate (for oil) is about 17.5 percent across all wells across the state. The royalty rate for gas is slightly lower (17.43 percent).” The industry paid $5 billion in total mineral royalties with $4 billion of this amount going to private mineral ownership royalties. Bangsund says oil operators were asked what portion of that amount came back to the state. “As long as it came back to North Dakota, that’s what we were interested in,” he says. “About 40 percent of that $4 billion comes back to North Dakota.” The study also demonstrates how other sectors of North Dakota’s economy benefit
Seeing Through to the End &Žƌ ŵŽƌĞ ƚŚĂŶ ϲϬ LJĞĂƌƐ͕ ǁĞ ŚĂǀĞ ƉƌŽǀŝĚĞĚ ĞŶŐŝŶĞĞƌŝŶŐ ĂŶĚ ƚĞƐƟŶŐ ƐĞƌǀŝĐĞƐ ƚŽ Ă ǀĂƌŝĞƚLJ ŽĨ ŝŶĚƵƐƚƌŝĞƐ ŝŶĐůƵĚŝŶŐ Žŝů ĂŶĚ ŐĂƐ͘ tĞ ŽīĞƌ ƚŚĞ ĨŽůůŽǁŝŶŐ ƐĞƌǀŝĐĞƐ͗ ŐĞŽƚĞĐŚŶŝĐĂů ĞŶŐŝŶĞĞƌŝŶŐ͕ ŶŽŶĚĞƐƚƌƵĐƟǀĞ ĞdžĂŵŝŶĂƟŽŶ͕ ĞŶǀŝƌŽŶŵĞŶƚĂů ĐŽŶƐƵůƟŶŐ͕ ŵĂƚĞƌŝĂůƐ ƚĞƐƟŶŐ ĂŶĚ ŵŽƌĞ͘ dŽ ůĞĂƌŶ ŵŽƌĞ͕ ǀŝƐŝƚ ǁǁǁ͘ďƌĂƵŶŝŶƚĞƌƚĞĐ͘ĐŽŵ
The Science You Build On. &Žƌ ŵŽƌĞ ŝŶĨŽƌŵĂƟŽŶ ĂďŽƵƚ ŽƵƌ ƐĞƌǀŝĐĞƐ͕ ƉůĞĂƐĞ ĐŽŶƚĂĐƚ͗ <ĞŶ :͘ ,ĂĂŐ / ϴϬϬͲϮϳϵͲϲϭϬϬ
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The BAKKEN MAGAZINE APRIL 2015
EXPLORATION & PRODUCTION
Change In Industry Spending, North Dakota, 2005-2013 Direct Impacts (billions 2013 $)
from oil and gas industry activity. For example, it created $11.3 billion in retail trade revenue and $9.3 billion for households, which includes royalties, lease bonuses, salaries, wages and other income. â&#x20AC;&#x153;This is a complex industry,â&#x20AC;? Bangsund says. â&#x20AC;&#x153;Iâ&#x20AC;&#x2122;ve been working with the industry for six separate studies, and every time we do this, I learn something new. We break the industry into segments that are consistent with what we think industry does.â&#x20AC;? The segments and their economic impacts are: â&#x20AC;˘ Exploration and development includes drilling and well completions, which generates $7.6 billion in direct impacts and $12.8 billion in secondary impacts. â&#x20AC;˘ Production and extraction includes well management and oil and gas extraction and production, which generates $7.7 billion direct impacts and $7.6 billion in secondary impacts. â&#x20AC;˘ Transportation and processing includes transporting oil and gas out of state and in-state processing and transportation, which generates $957 million in direct impacts and $1.9 billion in secondary impacts. â&#x20AC;˘ Infrastructure spending covers what the industry is spending to add infrastructure in the state, which generates $1.5 billion direct impacts and $3 billion in secondary impacts. The gross business volume of North Dakotaâ&#x20AC;&#x2122;s oil and gas industry is perhaps the best indicator of its explosive economic growth. The $15.3 billion total in 2013 represents a 72 percent increase over 2011 ($8.9 billion) and a 474 percent increase over 2005 ($2.7 billion). â&#x20AC;&#x153;What portion of that $15 billion do we get in North Dakota?â&#x20AC;? Bangsund asks. â&#x20AC;&#x153;In other words, not everything that the industry needs to produce a well comes from somebody in the state that can provide those goods and services. We estimated that about $7.3 billion of that $15 billion gets circulated through our economy. â&#x20AC;&#x153; Every dollar spent by the industry results in $1.48 in economic activity. Government received $4.4 billion from taxes, royalties, leases; licenses, permits, fees and donationsâ&#x20AC;&#x201D;money used to fund schools,
20 $16.2 billion
15 $10.9 billion
Production 2005 $1 billion 2013 $7.7 billion
10 $5.1 billion
5 $1.7 billion
0
Exploration 2005 $500 million 2013 $7.6 billion
Proc/Trans 2005 $153 million 2013 $957 million 897% increase
$3.4 billion
2005
2007
2009
2011
2013
SOURCE: NORTH DAKOTA STATE UNIVERSITY DEPARTMENT OF AGRIBUSINESS AND APPLIED ECONOMICS
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EXPLORATION & PRODUCTION
roads and infrastructure, law enforcement, parks and recreation. Finance, insurance and real estate account for another $4.5 billion in economic activity. Other sectors including business and personal services; communications and public utilities; professional and social services; construction; manufacturing, transportation and others contributed $12.7 billion to the economy. What everybody also knows about the oil and gas industry is that because of falling
oil prices, the booming statistics reflected in the 2013 study are likely to be reduced when NDSU looks at data two years from now. The question is: how much?
Future Study Results
“If oil prices remain in the current range, we’re going to see a pretty substantial pullback in the drilling activity,” Bangsund says. “We’ve already observed a fair reduction in the number of rigs. A lot of the companies have come forward with their inves-
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The BAKKEN MAGAZINE APRIL 2015
tor declarations. Their capital expenditures budgets are rolled back considerably from what they have been previous years. They’re simply stating up front that they’re not going to be spending the money that they have in the past.” North Dakota’s legislators are already taking this into account in their budget planning for the next biennium. The revised oil tax revenue forecast issued by the North Dakota Office of Management and Budget in mid-March estimates that the state’s total oil tax revenue during the 2015-‛17 biennium will be roughly $3.4 billion, down from the $4.2 billion forecast at the start of the year. This is based on the assumption that North Dakota’s production will average 1.1 million barrels of oil per day throughout the 2015-‛17 biennium. Pam Sharp, OMB director, expects North Dakota oil prices—always discounted 15 percent from West Texas Intermediate by the OMB—will range between $42/b and $52/b, a number more conservative than the legislature assumed in its January revenue forecast. While noting that the unforeseen drop in oil prices is a reminder that forecasting future economic trends is difficult at best, Bangsund believes that in 2015 and 2016, North Dakota’s oil and gas industry will see mixed economic impacts, mostly in the industry segments of production, processing and transportation. “The substantial drop in price is going to have an immediate effect on severance tax collections,” he says. “It’ll affect the royalties and other revenue streams that come from those wells. Those wells will still need to be maintained. They’ll still need to have employment associated with them. We’re still going to be adding wells. We’re not completely abandoning the drilling activities.” Both oil production tax triggers—the small and large trigger—will impact parts of the current and upcoming biennium. For the past five months of the 2013-‛2015 biennium, the small tax trigger will be in effect. The small trigger provides a reduction to producers in the extraction tax for new horizontal wells drilled in the month
EXPLORATION & PRODUCTION
after the previous month averaged less than $57.50 per barrel for West Texas Intermediate. â&#x20AC;&#x153;There have been so many things going on with the price of oil lately and no one can say where it is going to lead. Earlier, we didnâ&#x20AC;&#x2122;t know if the large trigger was going to be in place, but now it looks like it is definitely going to happen,â&#x20AC;? Sharp says. The large triggerâ&#x20AC;&#x201D;a tax reduction applied to all wells for the first 24 months of all wells in productionâ&#x20AC;&#x201D;will be in effect for the first 11 months of the 2015-â&#x20AC;&#x203A;2017 biennium, the OMB predicts. The large trigger is only turned off when WTI trades above $55.09 per barrel for five consecutive months. The large tax trigger could be in place from May 2015 until April 2016, according to the OMB. The January revenue revision only slated the large tax trigger to be in place for 10 months. While the presence of the large tax trigger impacts several budget allocations, it greatly impacts the resources trust fund. â&#x20AC;&#x153;That is funded by just the extraction tax,â&#x20AC;? Sharp says. â&#x20AC;&#x153;Once the big trigger is kicked on we donâ&#x20AC;&#x2122;t have any extraction tax for 11 months. It funds all of the statewide water projects. That is clearly something that is problematic when they were counting on a lot more money.â&#x20AC;? Despite low commodity prices and a reduction in the revenue generated from oil and gas, North Dakota should see an increase in sales and use tax, according to the OMBâ&#x20AC;&#x2122;s budget. In the upcoming biennium, sales and use tax revenues will total $2.87 billion. The 2013-â&#x20AC;&#x203A;2015 biennium revenue from sales and use tax will total $2.5 billion. Bangsund believes that while nobody can accurately predict the long-term overall impact of low oil prices, the near-term consequences will be more evident further into 2015.
dustry is going to be focusing even harder now on efficiencies and cost reductions than they were after the leases were secured.â&#x20AC;? Because production will continue at a high rate, Bangsund says economic activity in transportation and processing might exceed 2013â&#x20AC;&#x2122;s numbers. â&#x20AC;&#x153;The refining activity and the gas processing activity is going to continue even if the price of the inputâ&#x20AC;&#x201D;primarily gas and crude oilâ&#x20AC;&#x201D;goes down,â&#x20AC;? he explains. While some see low oil prices as a nega-
tive, Bangsund says there is a potential upside if prices eventually increase. â&#x20AC;&#x153;Some of these current economic conditions might result in efficiencies that the industry develops more quickly than they would have normally,â&#x20AC;? he notes. â&#x20AC;&#x153;In the long run, if oil prices rebound and weâ&#x20AC;&#x2122;ve developed new and better ways to get oil production out of the shale, that could be positive because it might allow these marginal areas to become producing areas if the economics were favorable.â&#x20AC;?
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â&#x20AC;&#x153;The companies are focusing on the most productive regions of the Bakken; probably the average productivity per well is going to go up. It wonâ&#x20AC;&#x2122;t be a one-for-one drop in production,â&#x20AC;? he says. â&#x20AC;&#x153;Weâ&#x20AC;&#x2122;re just not going to be drilling as many wells. The in-
&RUSRUDWH Â&#x2021; )LHOG <DUG
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THEBAKKEN.COM
31
EXPLORATION & PRODUCTION
Dollar In-Flows To ND
North Dakota, Export Base, 1990-2013 Million Constant 2013 Dollars
50,000
Federal Payments
45,000
Exported Services
40,000
Tourism
35,000
Oil/N. Gas Exp., Ext. & Refining
30,000
Coal Mining & Conversion
25,000
Manufacturing
20,000
Agriculture
15,000 10,000 5,000 0
1990
2000
2010
2011
2012
2013
SOURCE: NORTH DAKOTA STATE UNIVERSITY DEPARTMENT OF AGRIBUSINESS AND APPLIED ECONOMICS
The long-term prospect is still very positive for a considerable amount of oilfield development in western North Dakota, according to Bangsund. “We’re seeing a pullback now because of the low prices, but I haven’t heard any-
32
one suggest that we’re going to maintain the current economic climate over the next 20 years,” he says. “Everybody seems to think that prices will return and increase back to closer approaching what we had in 2014. If that’s the case, industry could put more rigs
The BAKKEN MAGAZINE APRIL 2015
back into that region. They could be drilling wells in areas that are not just the most profitable now.” Bangsund says the reason oil companies continue to invest billions of dollars into the Bakken for infrastructure projects is because experience has taught them that it’s a tremendous resource. “The resource is there and we know that it’s extensive; it covers a large geographic footprint,” he notes. “We also know that there are billions of barrels of oils left to be extracted. If we can get caught up with the growth that’s occurred to this point, the state would be in much better position to handle the ongoing development of this oilfield, which is likely to go on for many years.” And that’s a fact, not a punch line. Author: Patrick C. Miller Staff Writer, The Bakken magazine 701-738-4923 pmiller@bbiinternational.com
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PRODUCTS & TECHNOLOGY
Navigating Bakken Data Born of the frack sand business, Navport’s new downhole information service ushers in a new way to track Williston Basin activity By Luke Geiver
Sean Morgan wants to provide accurate, nonskewed downhole oil and gas data—“data that sings”––to every business entity linked to hydrocarbon production.
Since early 2014, Morgan and a small team of data analysts and industry veterans have been working to break into the lucrative unconventional oil and gas data sector by utilizing personal experience gained from time spent in the frack sand supply and distribution world. The team, led by Morgan, vice president of sales and operations, and Eric Foster, president, has developed a data subscription service that provides downhole well data to clients through multiple platforms with varying degrees of in-house analyst interaction. One particular group of clients—investors and analysts—receive simple data sheets showing individually selected exploration and production company information across the entire U.S.; some subscribers desire access to an online dashboard equipped with an activity meter for each individual U.S. unconventional play; certain customers work with data analysts to create customized reports (just as The Bakken magazine did for supplemental information for this story). Although the company name Navport may not yet be commonplace in boardrooms, field operations or analyst calls, the team believes its flexible approach to data analysis and experience selling and moving frack sand will change that.
34
The BAKKEN MAGAZINE APRIL 2015
PRODUCTS & TECHNOLOGY
Dunn County Well Completed
Average BOE/Well
Average BOE/Proppant ST
Halcon Resources
11
132,683
55
WPX Energy
26
101,700
64
Continental Resources Inc.
27
80,736
59
Hess Corporation
15
75,341
85
ConocoPhillips Co.
13
72,425
38
Operator
Kodiak Oil and Gas Corp.
16
72,124
37
QEP Energy Co.
43
71,604
48
XTO Energy/ExxonMobil
18
61,481
23
Marathon Oil
50
58,731
49
Occidental Oil and Gas
38
45,655
52
QEP HES 3% 3%
Average BOE/Well
85
Average BOE/Proppant
KOG 4%
MRO 18%
CLR 9% WPX 8%
132,683
Proppant Mass Market Share
OXY 10%
Top 10 Operators by Proppant Mass (short tons)
HK 11% XOM 13%
COP 16%
QEP KOG 3% 2% HES CLR 5% 5% WPX 8% HK 10%
MRO 23%
Completion Market Share Top 10 Operators by Completion Count
OXY 14% XOM 13%
COP 13%
THEBAKKEN.COM
35
PRODUCTS & TECHNOLOGY
Mountrail County Well Completed
Average BOE/Well
Average BOE/Proppant ST
EOG Resources Inc.
48
182,318
30
Marathon Oil
27
98,361
73
WPX Energy
32
88,419
52
Hess Corporation
59
69,627
66
Whiting Petroleum Corp.
55
67,495
63
Slawson Exploration Co.
14
66,782
29
Oasis Petroleum
41
52,151
46
Fidelity Exploration
26
48,443
46
Statoil
23
46,628
25
Operator
182,318 Average BOE/Well
73
Average BOE/Proppant
Fidelity WPX 3% 3% STO 6%
HES 20%
MRO 7% CLR 7%
Completion Market Share Top 10 Operators by Completion Count
OAS 10% WLL 13%
Fidelity WPX 2% 3% MRO 4%
CLR 9% OAS 7%
STO 5%
HES 12%
Proppant Mass Market Share
Top 10 Operators by Proppant Mass (short tons)
WLL 8%
EOG 37%
Slawson 12%
36
The BAKKEN MAGAZINE APRIL 2015
Slawson 13%
EOG 17%
PRODUCTS & TECHNOLOGY
Early Days Of Data
Before working on software and online data dashboards, Morgan worked for Preferred Sands, a major frack sand supplier, prominent in several U.S. unconventional resource plays. During Morgan’s early days, demand for sand was large and energy service providers required sand quantities, in some cases, only two to three weeks after signing a supply contract. “Unless you had product forward positioned into the basin, you couldn’t meet demands,” Morgan says. Because management didn’t want to turn down sand orders, several sand transloading site setups were arranged, many in the Bakken shale play. In the Bakken, as the locations of well activity evolved, and the amount of sand needed at them, it created
difficulties for Morgan and the team assigned to allocate sand volumes. “How do you know if you want to be in Berthold or Minot?” he says. On top of that, he says, “we needed to be within 100 miles of the client’s ending location because the sand drivers wanted to get three turns of sand delivery in during a single shift.” The only way to truly gauge production activity was to meet with sales associates designated to each unconventional shale region. Eventually, between 30 and 40 transload facilities were opened across the U.S., Morgan says, because the industry was evolving so quickly and there was no way to accurately predict the best sand unloading sites while producers were constantly changing plans and techniques. With the transload facili-
ties, the team quickly learned that backend costs—demurrage fees for rail cars filled with sand or on-site sand storage—were washing out perceived profits generated from supply contracts. After learning of the impact of backend costs, the team realized it could no longer commit sand volumes to transload facilities. “We needed a tool that could help us determine the best place for our sand,” Morgan says. The tool was data. And, it wasn’t outside data provided from other firms. After reviewing industry offerings, Morgan spurned the chance to pay for information and instead worked with an internal team to collect, analyze and ultimately utilize downhole data, producer plans and fracking trends to determine where frack sand was truly
meant to be. Shortly after, he was moved from the supply team and was tasked with helping the sand sales division understand and utilize data. “It all made us smarter about the marketplace,” he says.
Starting A Stand-Alone Service
Soon after the in-house sand data collection and downhole information effort started, Morgan and his team had earned the respect of Preferred Sands management and broke off into a separate company. Today, roughly one year after official launch, Navport is still a small team. The company believes its data is crucial to the industry because all the data—from pounds of proppant per lateral, to average barrel of oil produced per short ton of proppant—is spot
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37
PRODUCTS & TECHNOLOGY
Williams County Well Completed
Average BOE/Well
Average BOE/Proppant ST
Hess Corp.
20
84,220
78
Operator Kodiak Oil and Gas Corp.
65
80,131
35
Halcon Resources Corp.
6
78,155
33
XTO Energy/ExxonMobil
17
65,324
46
Statoil
36
61,765
34
Continental Resources Inc.
100
59,561
28
Whiting Petroleum Corp.
6
58,092
38
Oasis Petroleum
36
47,576
34
on. “The biggest challenge with data isn’t getting it,” Morgan says. “It is making the data make sense, making it sing.” Bringing numerical spreadsheets into harmony requires Navport’s analysts to sift through
vast amounts of data in search of outlying numbers that don’t make sense. In some instances, the team will find a well that shows an amount of proppant used that is physically impossible. Analysts will flag the particular
data set and remove it from the main data set. “We are constantly running quality control.” The data control efforts aren’t just for frack sand mining firms, suppliers or logistics firms. According to Morgan, financial
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The BAKKEN MAGAZINE APRIL 2015
FULL LINE OF CONTROL VALVES - PARTS & SERVICE
PRODUCTS & TECHNOLOGY
Slawson 4%
HK 4% CLR 13%
WLL 6% Zavanna 4% XOM 10%
Proppant Mass Market Share
Top 10 Operators by Proppant Mass (short tons)
STO 12%
KOG 12%
HES 6% OAS 7%
Average BOE/Well
CLR 12%
WLL 5% Zavanna 7%
84,220
HK 3%
Slawson 4%
Completion Market Share Top 10 Operators by Completion Count
XOM 8%
KOG 11%
HES 10%
STO 9%
OAS 9%
78
Average BOE/Proppant
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THEBAKKEN.COM
39
PRODUCTS & TECHNOLOGY
McKenzie County Well Completed
Average BOE/Well
Average BOE/Proppant ST
QEP Energy Co.
54
107,206
63
Hess Corp.
48
94,059
122
ConocoPhillips Co.
43
91,943
48
Continental Resources Inc.
35
87,374
49
XTO Energy/ExxonMobil
47
83,491
34
Newfield Exploration
60
75,654
47
Triagnle USA Petroleum
31
70,546
47
Whiting Petroleum Corp.
44
66,153
44
Emerald Oil Inc.
15
64,699
27
Oasis Petroleum
38
60,810
36
Amie Parenti, market data analyst created a unique, one-off Bakken report guided by our teamâ&#x20AC;&#x2122;s input. The exercise was meant to showcase the data offerings and analyst interaction process. For the report, we focused on four North Dakota counties: Dunn, McKenzie, Mountrail and Williams. Within the counties, we focused on overall proppant market
share by county, well completions and proppant pumped; proppant intensity tracking by county; proppant ratio tracking by county; operator market share per county; and, production results by operator per county. The resulting custom report revealed several informative takeaways about production variances between counties and
Average BOE/Well
122
Average BOE/Proppant
which operators are getting the most production from the least amount of proppant. For each county, Parenti provided information from the top 10 producing companies and compared each to each. During Parentiâ&#x20AC;&#x2122;s interpretative analysis of the data report, it was clear that although she and Morgan were not actually singing over the phone on
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our conference call, there was an unspoken harmony between the data and the reality of the Bakken. Author: Luke Geiver Editor, The Bakken magazine 701-738-4944 lgeiver@bbiinternational.com
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The BAKKEN MAGAZINE APRIL 2015
PRODUCTS & TECHNOLOGY
TPLM 5% NFX 7% WLL 8%
EOX OAS 3% 4%
COP 12%
Completion Market Share Top 10 Operators by Completion Count
CLR 9%
HES 11%
XOM 10% QEP 9%
TPLM 4%
STO 4%
NFX 6%
EOX 4%
COP 12%
Proppant Mass Market Share
Top 10 Operators by Proppant Mass (short tons)
WLL 7% CLR 12%
HES 6%
XOM 10%
QEP 13%
THEBAKKEN.COM
41
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44
The BAKKEN MAGAZINE APRIL 2015
PRODUCTS & TECHNOLOGY
Dealing With
RIG DECLINE Drilling product providers and consultants share insight on rig activity slowdown By Emily Aasand
To see the impact of low oil prices on the Bakken shale, look no further than North Dakota’s drilling rig count. Since January,
the rig count has been steadily dropping, according to the Department of Mineral Resources. January’s count was down 21 rigs from the previous month, February was down 27 and by mid-March, the state’s total rig count equaled 111—the lowest since April 2010. At press time, the rig count had fallen below 100. The Bakken isn’t the only major U.S. unconventional resource play incurring a declining rig count, or a slowdown in monthly oil and gas production. The U.S. Energy Information Administration’s recent Drilling Productivity Report also indicates a slowdown in oil production growth patterns in the Eagle Ford and Niobrara. The combined three plays are down roughly 24,023 barrels of oil per day (bopd). The estimates cover the months of March and April, and include the first projected declines in crude production in these regions since the first issue of DPR appeared in October 2013. The DPR shows sharp decreases in rig counts in all regions starting in January and February of this year. In the current oil price market, producers have begun to lay down rigs, idling the older, least-efficient ones first, leaving monthly production output dependent on the remaining rigs. Production may not depend entirely on the overall rig count, according to the EIA. Amidst lower oil prices, the 2008-‛09 recessions led to decreases in rig counts, but no decrease in production. At that time, lower rig counts were more than offset by increases in the productivity of remaining rigs, as more productive rigs required fewer days to drill and complete a well, recorded higher initial production rates, and were
DIPPED WITH A MANTRA: Summit Casing believes its commitment to face-to-face service and all-hour access—the Summit Standard— will help it grow and maintain its place in the oil and gas drilling business, despite the decline in rig activity. PHOTO: SUMMIT CASING
THEBAKKEN.COM
45
PRODUCTS & TECHNOLOGY
more than able to drill multiple horizontal wells from a single pad. “Because the base level of rig performance is so much higher now than several years ago, it is not clear that the productivity gains will offset rig count declines to the same degree as in 2008-‛09.” Overall, U.S. crude production numbers might remain at current levels for the short-term. Drilling rig numbers are down, however, and companies directly leveraged by rig count and well completions are incurring a variety of requests and changes to their respective businesses. Although the rig decline may appear to be negative, some firms are finding ways to benefit from an activity level slowdown.
Decreased Activity Requires Increased Focus
Summit Casing Equipment, a U.S.based drilling component manufacturer,
46
is dealing with the effects of declining rig counts. The decline for drilling products, including centralizers, a hinged collar placed on the outside of drill string casing that helps to keep the casing string in the center of the wellbore, has made Summit intensify its internal focus. “Our product is used during the drilling process, so if the drilling rig count goes down, that affects us because that’s less rigs we can sell our products to,” says Andrew Eldridge, CFO of Summit Casing. “Through these tough times, we’re really focusing on the quality of our product, and the service that we provide.” Summit Casing got its start in the industry 10 years ago in Elk City, Oklahoma, and has since grown to 10 locations throughout the U.S. Summit began manufacturing solid body centralizers five years ago and since then, has begun
The BAKKEN MAGAZINE APRIL 2015
WELL-PLACED SERVICE: During the activity slowdown, DTC Energy Group Inc. is working to match its experienced oil and gas consultants with clients, based on the experience level and desire of the individual client. PHOTO: DTC ENERGY GROUP INC.
PRODUCTS & TECHNOLOGY
manufacturing bow spring centralizers, composite centralizers and float equipment. â&#x20AC;&#x153;We have to be spot on and deliver on who we are if we want to come out of this thing better positioned than we were before,â&#x20AC;? Eldridge says. To do that, the company is continuing to push its service offerings that come with the drilling components. Summit equips regional field sales representatives with iPads, technologically advanced equipment and transportation allowing each manager to visit or service drilling rig locations throughout each region. At a time when cost cutting measures are happening at every level of the oil and gas sector, Summit believes it needs to refrain from cutting costs by cutting its face-to-face time in the plays it serves. â&#x20AC;&#x153;If we stick to who we are, we will be very well-positioned to take a larger share of the market and service more operators than we do today because we have had the opportunity to interface with them on the rig site and tell them our story,â&#x20AC;? according to Jeff Reynolds, vice president of sales for the company. The slowdown in activity has forced many businesses to increase internal focus and pinpoint the true value of their service offerings or products. While Summit believes
CASING MADE IN AMERCIA: Summit Casing manufacturers its products in the U.S., which allows it to speed up the order and delivery process for many of its customers. PHOTO: SUMMIT CASING
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QUALITY RETENTION: Summit Casing’s team says its products are neither the least nor the most expensive, but believes sacrificing quality in the name of cost-cutting will only hinder its long-term place in the industry. PHOTO: SUMMIT CASING
it has a value proposition linked to the quality of its components and its commitment to service (even if it means answering a phone call at 4 a.m. from a drilling rig site), others are pursuing the same focus through different means. Centek Group, a global provider of onshore and offshore drilling components, believes the current crude market provides great opportunity to get in front of customers to show how important Centek’s 48
centralizers are in cutting well costs by decreasing overall drilling days and the time it takes to reach total depth. In the current market, the team is working to highlight its product functions, many of which help to decrease total drilling days and in developing engineered solutions that support API best practices for cementing, reducing risk and rig time as well as enhancing the integrity of the well construction phase. The company has spent
The BAKKEN MAGAZINE APRIL 2015
and continues to spend time on research and development before introducing its products, including centralizers, into the field. The aim for its centralizer R&D was to provide a hybrid product that had all the benefits of a rigid centralizer and a bow spring centralizer without any of the detriments. “The field is a very different field right now,” says John Costine, North American sales manager at Centek. From the operator standpoint, we see a lot of people buying on upfront costs alone and subsequently dealing with a lot of remedial issues and overall higher well costs. Our product allows them to get to bottom more efficiently saving them costs related to rig time, crews and overall well construction time. Typically, we’ll save them several hours running in hole. Running in hole at gauge allows us to maximize standoff. We have a long history of cement bond logs showing that we have improved wellbore integrity. This provides piece of mind from an environmental standpoint and eliminates costly remedial work before going into the production phase. It is very important to communicate the total well cost, versus just the upfront product cost.” In many cases, the current oil price environment has pushed procurement managers and equipment buy-side decision makers to purchase product based on initial price, instead of overall value and service offerings included with the product. “Our product allows them to get to the bottom faster and to be more efficient with their rig time. Typically, we’ll save them several hours running in
hole. Our job right now is very important to show them the big picture of overall well costs versus just paying for a product upfront.” Centek’s ability to thrive during the slowdown is connected to its research and development efforts put towards a common industry equipment item. Centek’s centralizers were the first 100 percent heattreated,single-piece, nonweld product in the industry, according to Costine. The U.K. and Oklahoma City-based company produces a centralizer that is designed to run in hole at gauge, with no starting or running forces providing the highest amount of standoff, he added. “Our patents on our unique construction, metallurgy and heat treat process are what sets Centek apart,” says Costine. The Centek S2 centralizer is manufactured from a flat plate, is rolled then formed and then bulged into its shape, according to Cliff Berry, global sales and marketing manager for Centek. It is a single-piece unit, has no moving parts, and is rapidly becoming an industry leader for both liners and standard casing sizes, he added. The S2 is applicable for all applications—vertical and horizontal wells and can withstand high temperatures. It is manufactured to gauge and provides maximum standoff, eliminating cement channeling. Its bow spring design was created to allow for flexibility when encountering tight spots, yet, due to its single piece construction, it does not compromise on performance integrity, according to the company. Summit relies on the U.S.
PRODUCTS & TECHNOLOGY
THE CENTEK ADVANTAGE: Through expansive research and development efforts, Centek has created a suite of centralizers that it verifies can reduce drilling days and a rig’s ability to reach total depth in a well bore.
onshore market for revenue. The company manufacturers several U.S.-made products, a facet of the company that can help expedite the order and delivery process. “We manufacture it, we sell it. A huge differentiator for us is that all our centralizers and float equipment are manufactured in the U.S., which is quite rare.” In many cases, if a drilling rig engineer is in need of a speciality product, Summit can minimize downtime through its network of field sales representatives well-versed in product location. “We’re a small company and we compete against some of the largest in the world,” says Eldridge. “Our focus on our one product offering
model is really what sets us apart. It’s the quality of the product and the service that we provide that’s really of our legacy. Around here, we call it the Summit standard—going the extra mile, making the extra trip that needs to be taken.” Like many companies, Reynolds says it is working to cut costs wherever possible, but cutting its service and the crucial materials used to fabricate its drilling components will not happen. Although our profit margin will be adjusted in a depressed market, we are still going to provide that type of service because we think that it is a strategic point of difference,” Reynolds says.
Consulting Perspective
Drilling activity-related companies aren’t the only oil and gas firms impacted by a declining rig count. DTC Energy Group Inc., a Coloradobased oil and gas drilling and completion consultancy, has experienced decreased requests for service in its drilling supervision segment due to the current oil market. DTC Energy started as a an idea in mid-2010, when Robert Sylar and Luke Clausen began discussing a larger oilfield consulting firm that could expand into a broader area of the country. The Denver-based firm officially began doing business in 2011. As a consulting firm, DTC
PHOTO: CENTEK GROUP INC.
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STANDING FOR GROWTH: Summit Casing currently relies on the U.S. market, operating as a small business relative to other larger, global players such as Centek. But, because it offers a wide array of products, it believes weathering the rig decline is more than possible.
Energyâ&#x20AC;&#x2122;s drilling supervision has been impacted due to the substantial drop in drilling activity. â&#x20AC;&#x153;The market conditions have had an impact on some of our service lines,â&#x20AC;? says Clausen, co-owner and chief operating officer of DTC. â&#x20AC;&#x153;There are currently about 700 fewer drilling rigs operating in the U.S. than there were in the fall of 2014, so growth in that area has been a challenge. We have adapted to the current market by pushing harder on our other service lines to make up for the lack of demand for drilling supervision. We have also been working diligently with our customers to get costs in line with their new budgets.â&#x20AC;? Along with drilling supervision, DTC also provides profes-
PHOTO: SUMMIT CASING
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The BAKKEN MAGAZINE APRIL 2015
PRODUCTS & TECHNOLOGY
sional, on-site supervisors for completion, stimulation, workover, production, site preparation, construction, remediation and safety to oil companies. The supervisors work on location, overseeing oil and gas operations, and ensure the operator’s plans are being followed. “Our supervisors are instrumental in reducing time and costs for our clients while maintaining safe operations,” says Clausen. DTC Energy also provides on-site frack engineers who help minimize screen-outs and reduce overall completion costs. The engineers specialize in onsite hydraulic fracture treatment analysis and design while focusing on optimizing overall completion economics. Clausen says
his team is capable of providing real-time treatment adjustments to ensure that completion objectives are achieved. The company also provides project and operations management to oil and gas operators, offering services such as preparation and permitting along with the procurement of equipment and supplies. “One of the main factors that sets us apart from our competition is our ability and strong dedication to work closely with our customers to provide the right person for each job,” says Clausen. “We ensure we understand exactly what our customers are looking for in terms of experience, skill level and personality. Our diversification across the country allows us to
move people from region to region since we are not centric to basin or area.” DTC Energy is one of only a few companies in the oilfield consulting market that’s employee driven, which Clausen says is another differentiator for the company, and a reason it is able to withstand the current activity slowdown. “It’s important for us to operate as an employee-based company so that our supervisors can be provided for in their daily lives. This model has been proven beneficial as a recruiting tool as well.” Like most companies, DTC Energy has taken steps to position themselves to remain successful in the current oil price environment.
“As with any downturn, there is concern. However, we think DTC is positioned very well to ride out an uncertain market,” says Clausen. “We expect, as with every slowdown in our sector, that smaller companies will not be able to survive and that there will be opportunities as oil prices recover. We believe there will be potential to grow or add service lines when we come out of the downturn. Overall, we see the downturn as an opportunity and are excited about the future at DTC Energy.” Author: Emily Aasand Staff Writer, The Bakken magazine 701-738-4976 eaasand@bbiinternational.com
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Citadel Advisory Group, a boutique investment banking firm serving oil and gas related industries, recently surveyed oil and gas service companies to understand where clients stand financially in the current oil price environment. The survey, which was open Feb. 4-16. and surveyed owners and C-level executives of more than 500 privately held U.S. and Canadian companies, came to flourish as Citadel began receiving questions, guidance and reassurance about the current oil price market. â&#x20AC;&#x153;As oil prices declined, we were flooded with calls from our network of service companies, as well as investors, wanting insight from their peer group,â&#x20AC;? said Chris Frevert, managing director of Citadel. â&#x20AC;&#x153;Executives wanted guidance; some just sought reassurance.â&#x20AC;? Citadel found that 92 percent of respondents indicated their top customer has recently requested price reductions in an effort to counter falling oil prices. Of those, roughly 12 percent
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shared that rate reductions costs?â&#x20AC;? Citadel found that topping 25 percent were more than 32 percent requested from their top were considering reducing three customers. The data workface pay, while 25 pershowed the negotiated recent were not considering ductions were more favorany other reductions. Othable to the service provider reductions companies er, Citadel said. are considering include: â&#x20AC;&#x153;Over the last couple Changes to benefit proof years, majors have been grams (7.1 percent), reducgetting very good at pushtion in number or size of Frevert ing down requirements and locations (7.1 percent), sale work that was once their of assets (8.9 percent), reresponsibility on support service compa- duction or change in service line (7.1 pernies without compensation. Unrealistic cent) and other reductions (12.5 percent). concessions are being requested despite Another question asked was â&#x20AC;&#x153;In relatively low margins,â&#x20AC;? said one survey your opinion, where do you anticipate the respondent. price of WTI to be on June 30, 2015?â&#x20AC;? The survey also found that more Citadel reported that more than 50 perthan 26 percent of service providers ex- cent of respondents believe the price will pected work volume to decrease by more be between $56 and $65 per barrel, and than 25 percent, and nearly 30 percent nearly 30 percent believe the price will said its customers have not provided range between $46 and $55 per barrel. guidance on work volume. Of those surveyed, 14.6 percent said One question asked was â&#x20AC;&#x153;Aside from the Bakken was responsible for the largest headcount: Which of the following are percentage of its revenue, which comes you considering in an effort to reduce in third only to the Niobrara and Powder
River Basin (31.7 percent) and the Eagle Ford shale play (17.1 percent). And of the segment of the oil and gas stream that represents the largest percentage of business, 19.5 percent responded with drilling, 39 percent said completions, 29.3 percent said production, 7.3 percent responded with midstream (pipeline) and 4.9 percent said other. Frevert said that comments by respondents provided insight into how the industry feels about declining oil prices. Comments ranged from equipment managers saying, â&#x20AC;&#x153;If drilling activity does not pick up soon then it will be a very rough Q2 and could be a devastating second half of 2015 for manufacturing companies in the oil and gas sector,â&#x20AC;? to technical service providers saying, â&#x20AC;&#x153;Weâ&#x20AC;&#x2122;ve had our second best month ever in January and February will be good as well. We are concerned we wonâ&#x20AC;&#x2122;t have the equipment to handle the work load or the personnel for field installs.â&#x20AC;?
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ROCK drill site
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Q M A T. C O M 5-ACRE MAT DRILL SITE
MAT drill site
AFTER ROCK DRILL SITE
Disadvantages - Damaging native farm land - Loss work time due to unsafe work surface - Delays in drilling - Unable to access due to bad weather - Wasting unnecessary amounts of rock - Unnecessary extra cost - High reclamation expense
WORLDS LARGEST SUPPLIER
AFTER MAT DRILL SITE
Advantages - No reclamation cost - Reduce the environmental impact - Reduce the amount of rock on native farm lands - Minimize unnecessary accidents - Mats provide a safe and stable work surface - 24/7 all-weather access with no down time - Potential to drill one to two more additional wells per year - Reduce the amount of truck traffic on roads - No additional cost - Protect existing flowlines
MANUFACTURING SINCE 1974